Thirty Five rigs were performing both drilling and completion activities in as many wells in Nigeria’s Niger Delta and the Benue Trough in March 2025.
It was a high mark in the country’s drilling activity in the last 10 years. Throughout 2017, for example, rig activity numbers were no more than 22.
28 rigs were drilling and seven rigs were completing. Two wells were being tested and two rigs were rigging up, as of Mid-March 2025.
Conversely, in Angola, the total number of rigs carrying out any operation has remained flat at 13 for the last three months and has moved between 12 and 14 in the last one year.
Although drilling has been close to this level in Nigeria since October 2024 (26 on average, compared with 28 drilling in March 2025), the remarkable thing about the March 2025 figures is the number of completions going on (7, compared with an average of 4 over the period from October 2024 to February 2025).
There was a completion going on at Newcross Petroleum operated Ekulama field in Oil Mining Lease (OML) 24; another completion was going on at Halkin’s Atala field and yet another by Tulcan Energy on Tom Shot Bank field.
Yet another data point: the OML 30, which hosted three rigs in March 2025, had never witnessed any drilling since the asset was purchased from Shell/ENI and TOTAL in 2012 until the current campaign began in 2024. Yet in March 2025, it hosted one faulty unit for work over operation, one functioning unit for another work over and a third unit for infill drilling. Heritage Oil Services which operates the OML on behalf of Shoreline Resources, was the third busiest company with the drill bit in the country, after SEEPCO and Seplat Energy. Rano Acrete (the upstream subsidiary of the petroleum product seller A. A Rano), was also drilling.
The difference in increase in rig activity between a Angola and Nigeria has not shown up considerably in oil production numbers. Nigerian crude output dropped from 1.54Million Barrels of crude a day in January, to 1.46MMBOPD in February and slipped to 1.44MMBOPD in March 2025. Angola’s crude output in January was 1.04MMBOPD; in February it was 1.054MMBOPD and in March 2025 it was 1.053MMBOPD.
Nigeria’s output is complicated by evacuation challenges in ways that Angolan output is not. There is also the geology factor; 65% of Nigerian production is onshore while only 25% is in deepwater. Angola is at least 80% deepwater.
These production figures versus rig activity numbers also challenge the notion that rig count is a leading index of industry’s commercial health. The truth is that 100 land rigs in Egypt are unlikely to deliver what 40 land rigs will do in Nigeria.
Two of the world’s largest deepwater drillers are seeing a progress to higher deepwater rig utilisation between now and 2029, with Africa, in particular, playing strongly in the rebound.
Ghana and Côte d’Ivoire are expected to welcome a deepwater rig each between the fourth quarter of 2025 and first quarter of 2026, (for between six to 12 months each), according to Transocean, the fourth largest offshore drilling contractor by fleet. In Nigeria, Shell has awarded a deepwater rig contract in the last two months and ExxonMobil and Chevron are expected to bring in a rig each between the end of 2026 and early 2027, the company said during a recent conference call.
A similar presentation by Valaris noted that “two multiyear programmes with IOCs are presently in tendering phase in Nigeria”. They are a part of “ten (10) long term deepwater drilling programmes expected to start between 2026 and 2027 offshore Nigeria, Côte d’Ivoire and Mozambique”. Valaris is the third largest offshore drilling contractor by fleet size. As of June 2024, it had five deepwater rigs working offshore West Africa.
The requirements are for drillships and semi-submersible rigs.
Transocean expects “three long programmes to commence in Mozambique by 2027”.
Valaris especially declared during its earnings call: “Offshore Africa remains the most active area for future floater operations”.
Deepwater drilling had tended to be less robust than drilling in other terrains in the eight years leading up to 2023, when a rebound began to happen. Activity in Africa, especially West Africa, had been even slower than those other parts of the world, notably South America and the US Gulf of Mexico, where deepwater oilfield operations are a regular feature. “The last piece of the golden triangle has now been woken up”, Transocean said.
Both Transocean and Valaris expect deepwater drilling in Namibia to ramp up between late 2027 and late 2028. TOTAL’s Venus field development “could generate six to eight rig years of work”, Valaris testified. This is a hint that development drilling on the Venus field is not expected to commence before 2027.
The two companies expect an uptick in drilling in the Egyptian deepwater segment of the eastern Mediterranean from late 2025, with Transocean specifically referencing bp’s operations.
The optimism for a bounce in deepwater rig activity comes against the backdrop of “broad market uncertainty”, heightened, in recent weeks, by “trade tension and OPEC announcement”. But most of the deepwater projects that inform this optimism are long term programmes, the companies said. It is the view of both Transocean and Valaris, that the uncertainty that has pushed oil prices to the $59-$62 per barrel range, has not impacted the likelihood of those projects happening in the 2026 to 2029 timeline.
The Norwegian minnow BW Energy has announced that a significant new oil discovery with good reservoir has been made at the Bourdon prospect, located on the Dussafu Marin Permit offshore Gabon.
Evaluation of logging data and formation pressure measurements confirm approximately 34 metres of pay in an overall hydrocarbon column of 45 metres in the Gamba formation, making it the largest hydrocarbon column discovered to date in the Dussafu licence. The well was drilled by the Norve jack-up rig to a total depth of 4,135 metres.
“The discovery will enable the Company to book additional reserves not included in its 2024 Statement of Reserves”, the company declared.
BW Energy’s 2P reserves in both its Gabonese and Brazillian licences totaled 229.2Million Barrels of Oil Equivalent as of December 31, 2024. They do not include its Kudu field offshore Namibia.
Developed assets include the Dussafu and Golfinho licences. Discoveries include the north flank of Hibiscus Main and the northern extension of Hibiscus South (in Gabon). Non-developed assets include the Maromba licence where the project final investment decision is subject to conclusion of project financing activities.
“The Bourdon appraisal well again confirms the significant resource potential of the Dussafu licence, which holds multiple additional prospects,” said Carl K. Arnet, CEO of BW Energy. “We will now carefully review the drilling results, but initial data indicates the potential for establishing a new development cluster with a production facility following the MaBoMo blueprint. We are evaluating a second sidetrack to further appraise the discovery”.
Bourdon is located approximately 15 kilometres west of BW Adolo FPSO and 7.5 kilometres southeast of the MaBoMo facility.
Bourdon is the final operation in the current Dussafu drilling campaign that has now resulted in four significant oil discoveries and eight new production wells across the Hibiscus / Ruche hub which, in addition to the six pre-existing wells at the producing Tortue field, has increased total gross production on the block to around the 40,000Barrels of Oil Per Day level.
By Sully Manope, Southwest African correspondent, in Windhoek
TGS, has competed the reprocessing of the Block 16 GeoStreamer MC3D seismic dataset in Angola’s Lower Congo Basin, in partnership with Agência Nacional de Petróleo, Gás e Biocombustíveis (ANPG).,
Block 16 is located between the two most prolific Angolan blocks: the TOTAL operated Block 17 and the ExxonMobil operated Block 15, but it has not delivered any significant discovery since deepwater exploration began in the early 1990s.
Shell made two sub commercial finds: Bengo(1994) and Longa (1995), in Upper Miocene reservoirs, located in the northern section of the block, a year before TOTAL made its first discovery: Girassol (Block 17) and three years before ExxonMobil encountered Hungo (Block 15). With lacklustre appraisal results and duster after duster, the UK major reassessed its options and walked out of the country.
Example of a full-stack Kirchhoff pre-stack depth migrated (KPSDM) section through the reprocessed ANG Blk 16 GeoStreamer MC3D dataset
TGS’ February 26, 2025 announcement, notes that the company’s decision to revisit data coverage in Block 16 was prompted by “resurgence in exploration in the deepwater Lower Congo Basin in recent years, with numerous significant discoveries being made and rapidly brought on stream”.
The company claims: “This 3,684-square-kilometre rejuvenation project utilizes modern depth processing workflows to deliver enhanced imaging beyond the original data, enabling detailed evaluation of deeper target plays in both post-salt and pre-salt sections”, TGS says in a release,
Angola’s Block 16 has remained largely underexplored since the early 2010s, with the most recent exploration well drilled in 2013. While the better known seismic images have been of prospects in the northern section, “a recent re-evaluation of wells in the Lower Congo Basin has identified oil recovery from Upper Miocene reservoirs in the southern part of the survey area”, TGS claims.
“The survey also provides partial coverage of the Tchihumba Field, a marginal field development opportunity currently being marketed by ANPG”, the Norwegian company notes.
“Discovered in 2003, Tchihumba contains hydrocarbon-bearing zones within Upper Miocene, Lower Miocene, and Oligocene sands, with recoverable volumes estimated at approximately 136Million barrels. Additionally, the Lumpembe-1 oil discovery on Block 15/06, drilled in 2023 and currently undergoing development studies, falls within the survey’s extent”.
The South African Independent Rhino Resources, has reported the conclusion of drilling of the Sagittarius 1-X well, in Petroleum Exploration Licence (PEL) 85 in Block 2914, offshore Orange Basin, Namibia.
Partners in PEL 85, in addition to Rhino Resources (42.5% interest), include Azule Energy, the joint E&P venture in Angola between bp and ENI, which also holds a 42.5% interest; the state hydrocarbon company NAMCOR (10%) and Korres Investments (5%).
Rhino’s terse statement did not disclose details of any penetrated hydrocarbon reservoir and the tone of its message was bland.
The Sagittarius 1-X well, which spud on 18 December 2024 using the Noble Venturer drillship, reached total depth (TD) on February 6, 2025, the statement said.
“The well penetrated Upper Cretaceous targets and intersected a hydrocarbon reservoir, with no observed water contact”, Rhino added.
“Intensive wireline logging operations allowed for the collection of hydrocarbon samples and sidewall cores. Fluid and reservoir properties will be confirmed with laboratory analysis”, the company explained.
“The drilling operations on the Sagittarius-1X well have now concluded and the rig has moved to drill the second well in the programme (Capricornus) which will test a different fairway”, the statement concluded.
Various oil industry analysts including myself were shocked to hear the news on January 9th 2025 that Shell had written down its holdings in deepwater Namibia by $400 million. This has led to many analysts asking, “Whatever is going on in deepwater Namibia”?
Early Excitement
Only three years ago Shell electrified the world’s oil industry with the announcement of the discovery of light oil and associated natural gas in the Graff-1X exploration well in the deepwater Orange Basin. The reservoirs were described as Upper Cretaceous marine sandstones. Almost immediately thereafter TOTALEnergies announced that the deepwater Venus-1X exploration well had discovered oil and associated gas in high-quality Lower Cretaceous sandstones. In 2023, Galp Energia added excitement with their announcement of the Mopane oil discovery. Following the Graff discovery, Shell announced oil and gas discoveries in the La Rona, Lesedi, Jonker and Enigma exploration wells. In total, five discoveries were made by Shell. Within a span of only three years, the Orange Basin had risen to become one of the world’s top-rated areas for oil exploration.
This leads to the critical question: what new information is currently available which significantly downgrades the deepwater Namibia? Or is there still room for optimism? I had to ask myself: why does Shell’s acreage in the Orange Basin have technical problems whereas these have not been reported by TOTALEnergies nor by Galp Energia?
Within the oil industry’s geological community, there has been a lot of discussions on the internet about why Shell has downgraded its Orange Basin holdings. The overall consensus as summarized in the UK-based publication GEOExPro (October 2024) is that chlorite cementation probably has had a detrimental effect on the reservoir properties. Such impurities can lead to lower oil recovery rates. However, what is most puzzling is that neither Galp Energia nor TOTALEnergies have reported similar problems in their discoveries.
Figure 1: From Sintana Energy’s website, January 15, 2025
Mopane Oil & Gas Field
In mid-2024, Galp Energia completed the drilling of two wells in Petroleum Exploration License (PEL) 83 where it has a high 80% working interest. State-owned Namcor has a 10% working interest as well as Namibia-based Custos Energy with a 10% working interest. Custos Energy is a Namibian indigenous company. The initial discovery well, Mopane-1X was followed by Mopane-2X, an exploration well located eight kilometres (8km) westwards. Namcor stated that Mopane-1X had discovered “a substantial column of light oil in high quality reservoir-bearing Cenomanian and Turonian age sands”. Galp declared that with Monpane-2X, “significant light oil columns were found in high-quality reservoir sands”. In April 2024, Galp announced that well tests in the Mopane-1X reached 14,000 barrels of oil per day equivalent which was the maximum allowable limit for testing. The oil was light oil with low viscosity, minimal CO2, and no H2S.
“The statistics indicate that of twelve exploration wells drilled by Shell, TOTALEnergies, Galp and Chevron, nine wells were declared as oil discoveries and only three dry holes indicating a success rate of 75%. On a worldwide scale, such a success rate is unprecedented. The statistics indicate that of twelve exploration wells drilled by Shell, TOTALEnergies, Galp and Chevron, nine wells were declared as oil discoveries and only three dry holes indicating a success rate of 75%. On a worldwide scale, such a success rate is unprecedented.”
In November 2024, Galp drilled and completed appraisal well Mopane-1A. Galp announced “light oil and gas-condensate reservoir-bearing sands with good porosities”. In January 2025, Galp completed appraisal well Mopane-2A and announced that the reservoir consisted of “good quality” sands with “good” porosities and permeabilities, high pressures and low fluid viscosities, minimum concentrations of carbon dioxide and no hydrogen sulfide. Galp also stated that “in line with the previous Mopane wells, no water contacts were found”. Industry watchers like myself wonder why Galp described the sands in Mopane-1A and Mopane-2A as only “good quality” whereas in the first two wells the reservoirs were described as “high quality”. Possibly the reservoir quality decreases in a westward and southern direction. In the meantime, Galp is now drilling Mopane-3X located about 15 km southeast of the Mopane field.
Shell’s announcement of their write down of their Namibia holdings could be viewed by the international investors as being extremely negative for deepwater Namibia. However, Galp Energia’s stock market price has held up very well, which implies that the worldwide international investment community is not overly concerned about Shell’s pessimistic assessment (Figure 1). Galp’s current stock market capitalization stands at a healthy Euro 11.8Billion ($12.3Billion). A similar stock market performance has been achieved by Toronto, Canada-based Sintana Energy which has a 4.9% interest in Mopane through its indirect interest in Custos Energy. Sintana’s current stock market capitalization is Cdn$295Million ($205Million).
Figure 2: Galp Energia share price in Euros. The share price jumped from Euro 14.0 to over Euro 20.0 after the drilling of Mopane-1X and Mopane-2X. Galp’s shares trade on the Euronext Lisbon stock exchange in Portugal.
Figure 3: Sintana Energy share price in Canadian dollars. Sintana’s shares trade on the Toronto Stock Exchange (TSE) Venture Exchange (TVX).
Currently, Rhino Resources is operator of PEL 85 and is drilling the Sagitarius-1X exploration well. Rhino’s partners include Azule Energy which is the BP-Eni 50:50 joint venture, Namcor and the Namibian company Korres Investments. Rhino Resources is a privately owned South African company and holds 42.5% interest in PEL 85 along with Azul Energy holding 42.5%, Namcor 10% and Korres 5%. At an oil industry conference last year in Cape Town, Maggy Shino, Namibia’s Petroleum Commissioner described Sagitarius as follows: “This is one of the most amazing prospects I have ever seen in Namibia. It does not get better than this”. If Mopane-3X and Sagitarius-1X are successes, this would bode well for the Orange Basin. However, if either are dry holes, this would blow a cold wind over deepwater Namibia.
Chevron Dry Hole
A cold wind did blow recently over deepwater Namibia with Chevron announcing on January 15, 2025 that their first exploration well in Namibia, Kapana-1X drilled on PEL 90 was a dry hole. This well was drilled 60 km west from Mopane. PEL 90 covers 5,433 sq km in water depths of 2,300 – 3,300 metres. Chevron is operator of PEL 90 with a 90% working interest and partnered with Namibia-based Trago Energy which holds the remaining 10%. Sintana Energy has a 5% carried indirect interest in PEL 90 in the initial exploration phase. Sintana acquired its interest through its acquisition in March 2022 of 49% of Trago Energy which is a wholly owned subsidiary of Custos Energy.
The statistics indicate that of twelve exploration wells drilled by Shell, TOTALEnergies, Galp and Chevron, nine wells were declared as oil discoveries and only three dry holes indicating a success rate of 75%. On a worldwide scale, such a success rate is unprecedented. However, some analysts have lingering concerns about the commercial viability of some of these discoveries.
TOTALEnergies Moving Full Speed Ahead
Two weeks ago, rumours began to surface that TOTALEnergies may have a major discovery in the Tamboti-1X exploration well. This well appears to be targeting the northeastern extension of the fan complex discovered by Mangetti-1X. TOTALEnergies mentioned that the structure targeted by this well could hold one billion barrels of oil resource. A press release has not yet been issued. Last October, TOTALEnergies CEO Patrick Pouyanne told analysts that the first FPSO on Venus will be designed to produce 160,000 barrels of oil per day and 500 million cubic feet of gas daily. The development is expected to be sanctioned in mid-2025 and on production by 2029. Multiple FPSOs will be needed for the full development of Venus. A major challenge for the development of Venus is the need to reinject the gas at a reasonable cost. Excessive costs could conceivably make the project non-economic. This will require leading edge technology since never before has reinjection of gas been carried out in 3,000 m of water.
Estimates of Oil & Gas Resources
Galp estimated that the Mopane discovery holds over 10Bllion barrels of oil in-place. By using a recovery factor of 25%, my “back of the envelope” estimate of the recoverable resources for Mopane are 2.5Billion barrels of oil. According to Namcor, Venus holds 2Billion barrels of recoverable oil out of an in-place resource of 5.0Billion barrels. This implies a recovery factor of 40%. Namcor has also indicated that they estimate almost 9.0Trillion cubic feet of associated gas has been found by TOTALEnergies and Shell.
All of the oil discoveries throughout the Orange Basin are gas-rich so there are also concerns about what to do with the gas. Flaring is not an option. Due to the deep water which ranges from as deep as 3,000 metres for TOTALEnergies to 2,000 metres for Shell and 1,600 metres for Galp, a gas solution will be complicated and expensive.
None of the discoveries in the Orange Basin have yet been declared commercially viable. None yet can be classified as reserves since reserves are volumes of oil which have been determined to be economically producible by the operator, independent consultants, and the Government of Namibia.
Where Is This All Going?
Has Shell unfairly tarnished the heretofore outstanding reputation of the deepwater Orange Basin? Perhaps Shell’s corporate threshold for commercial success is much higher than that of Galp and TOTALEnergies? However, I believe there are other companies such as Petrobras, TOTALEnergies or Chevron who could be very willing to partner with Namcor and develop Shell’s discoveries if Shell walks away. You can also be sure that ExxonMobil remains interested in opportunities in the Orange Basin.
One day after Shell announced the write down, Namibia’s Ministry of Energy and Mines issued a strongly worded two-page rebuttal which included the following: “While the Shell write down is unfortunate, we believe that we have barely begun to scratch the surface of our country’s offshore resources. We remain confident that ongoing exploration efforts will reveal commercial opportunities and look forward to delivering first oil production in the near future”.
For the past fifty years I have been involved hands-on in worldwide oil and gas exploration. I have also followed the oil industry as a consultant and analyst. I fully agree with the Namibians. It is still early days in Namibia. This is classic frontier oil exploration in a minimally evaluated super-large sedimentary basin. This story is not yet finished. Stay tuned.
Biography
Tako Koning is Holland-born, Canada-raised and resides in Calgary. He was involved with the evaluation of Namibia’s Kudu gas field from 1995 – 1997 when he was portfolio manager with Texaco in Luanda, Angola. At that time, Shell was operator of Kudu and Texaco had a 15% working interest in the field. Since that time, he has had an abiding interest in Namibia’s oil industry. He closely follows the latest news coming out of Namibia. He has travelled several times in Namibia for business and also as a tourist. His view is that Namibia is magnificent with its deserts, spectacular coastline, wildlife, and numerous national parks.
Koning has a B.Sc. in Geology from the University of Alberta and a B.A. in Economics from the University of Calgary. He worked worldwide for Texaco for thirty years and subsequently he continued to work in Angola for Tullow Oil and the consultancy of Gaffney, Cline & Associates. During his fifty-year career, he lived and worked for seven years in Indonesia, three years in Nigeria, and twenty years in Angola and the remainder in Calgary. He is pleased to share his knowledge of Namibia in this article. He has been an active member of the International Advisory Board of Africa Oil + Gas Report ever since the publication was founded in 2001 by Toyin Akinosho in Lagos, Nigeria.
Galp Energia encountered a new reservoir and penetrated one of the three known zones in its latest appraisal of the Mopane structure, offshore Namibia.
Mopane 2A found both (1) “a hydrocarbon column of gas-condensate in the AVO-3 reservoir, with a thin net pay in the reservoir sweet spot,” and (2) a hydrocarbon column of light oil in a smaller reservoir-a previously un-penetrated one designated AVO-4, Galp reported.
Notwithstanding their relatively small sizes in the western part of the Mopane structure, the two reservoirs exhibited “good quality sands, with good porosities and permeabilities, high pressures and low fluid viscosities characteristics, with ‘minimum’ concentrations of carbon dioxide and no hydrogen sulphide”, Galp explained.
In line with all previous Mopane wells, “no water contacts were found,” the Portuguese explorer noted.
Galp will now move the Saipem-owned Santorini drillship to the Mopane-3X exploration well location, targeting two stacked prospects — AVO-10 and AVO-13 , as part of the ongoing exploration and appraisal campaign in the Mopane complex.
Galp (80%, operator), together with its partners, state hydrocarbon company NAMCOR and the Namibian indigenous player Custos (10% each), discovered the Mopane field in water depths up to 1,680metres in the country’s offshore Orange Basin with Mopane-1X (well #1) in January 2024, encountering “significant oil columns containing light oil in high-quality reservoir sands at two different levels, AVO-1 and AVO-2”, the company said in release at the time.
In March 2024, the rig moved to the Mopane-2X location (well #2), “where significant light oil columns were discovered in high-quality reservoir sands across exploration and appraisal targets, namely AVO-3, AVO-1, and a deeper target”, Galp had explained. “In particular, the Mopane-2X well found AVO-1 to be in the same pressure regime as the Mopane-1X discovery well, around eight kilometres to the east, confirming its lateral extension.
“Testing operations followed suit, in April 2024, with a Drill Stem Test (DST) performed in well #1. The reservoir log measures confirmed good porosities, high pressures, and high permeabilities in large hydrocarbon columns. Fluid samples presented very low oil viscosity and contained minimum CO2 and no H2S concentrations.
“Considering the successful first phase of the exploration campaign, partners moved towards a Four (4)-well and Two (2) DST Exploration & Appraisal (E&A) campaign.
“In November 2024, Mopane-1A (well #3) encountered light oil and gas-condensate in high-quality reservoir-bearing sands, once again indicating good porosities, high permeabilities, and high pressures, as well as low oil viscosity characteristics with minimum CO2 and no H2S concentrations. Together with the Mopane-1X (well #1) and Mopane-2X (well #2) findings, this appraisal well confirmed the extension and quality of AVO-1.
“In December 2024, Galp and its partners decided to retain the Santorini drillship to continue the ongoing E&A campaign during the southern hemisphere summer taking advantage of favorable market conditions. Mopane-2A (well #4) was spud on December 1, 2024 to appraise AVO-3, one of the zones intercepted by the earlier Mopane-2X well”.
The partners are currently carrying out a high-density and high-resolution proprietary 3D seismic campaign over the Mopane complex.
Portuguese explorer Galp Energia, has reported that its highly anticipated appraisal well has “confirmed the extension and quality” of the primary reservoir encountered in the Mapone-1 discovery offshore Namibia.
This appraisal, Mapone-1A, spud on October 23, 2024 “hit light oil and gas-condensate in its main objective”, the company said in a release over the last weekend.
Mopane 1X, Mopane 2X and now Mopane -1A, are all located in Petroleum Exploration License 83 (PEL 83).
The release of the drill results bumped up the share price of Toronto-listed Sintana Energy, which maintains an indirect 49% interest in Custos Energy (Pty) Ltd., which in turn owns a 10% working interest in PEL 83. NAMCOR, the National Petroleum Company of Namibia, also maintains a 10% working interest.
This appraisal well is the first of an up to four well programme potentially consisting of two exploration wells and two appraisal wells. This second campaign on PEL 83 is predicated on providing additional insights into the scope and quality of the Mopane complex.
Galp Energia, the operator, got the entire hydrocarbon industry to sit up and take notice when in April 2024, when it claimed that the Mopane complex could hold as much as 10Billion barrels of oil equivalent in place.
“Galp and its partners will continue to analyse and integrate all new acquired data, whilst progressing with the upcoming activities, which include E&A wells, and a high-resolution proprietary three dimensional (3D) seismic campaign set to start in December 2024”.
TOTALEnergies is facing an expected hurdle in its quest to evaluate South African prospects it considers to be contiguous with its discoveries in neighboring South Africa.
With court papers in their hands, a small fishing community is standing in the way of the French major’s regional understanding of the exploration prospect straddling Namibia and South Africa.
The Aukotowa small-scale fisheries cooperative, and environmental justice organisations The Green Connection and Natural Justice, are asking the Western Cape High Court to stop TOTAL from exploring for oil and gas off the coast.
Such ‘don’t explore in my backyard’ actions are the rule in South Africa, and TOTAL has experienced some of them in the past: indeed the company has withdrawn from an offshore project off the South coast as a result of similar agitations, but it has made the exception to go ahead with exploration in the Deep-Water Orange Basin between Port Nolloth and Hondeklipbay, between 188 km and 340 km from the coast. Its initial plan will include up to ten exploration well drills.
TOTAL wants to trace the significant discoveries it made in Wenus structure offshore Namibia into South Africa by launching a regional exploration drilling programme in the coming years in both Namibia and South Africa. The French supermajor is also taking advantage of its leading acreage position in South Africa, to sweep the region for leads, prospects and developments.
TOTALEnergies has built a strong acreage position in the Orange basin (straddling Namibia and South Africa) and South Outeniqua basin (in South Africa).
“This fully operated portfolio covers more than 220 000 km² over seven (7) Blocks and has been grown through careful pro-active New Venture activity founded on solid regional synthesis works”, says Fleury et al. Looking back at the path towards the Venus discovery, TOTAL’s geoscientists say that the first task was the de-risking of the petroleum system: “TOTALEnergies’ efforts to evaluate the frontier deepwaters of the Orange and Cape Basins began some 10 years ago”.
The Aukotowa small-scale fisheries cooperative, and environmental justice organisations The Green Connection and Natural Justice are opposing the environmental authorisation for the project by the Department of Mineral Resources (DMR) and the Department of Forestry, Fisheries, and the Environment (DFFE). They are arguing that natural gas is carbon-intensive and should not be part of South Africa’s just transition and commitment to net-zero emissions by 2050.
TOTAL’s environmental impact assessment argues that natural gas is a “transition fuel” and “is included in the energy mix of South Africa to serve as a transition or bridge on the path to carbon-neutrality from 2050 onwards (in terms of the Paris Agreement) and provide the flexibility required to complement renewable energy sources”.
But the activists say the government has failed to assess the ecological impacts the exploration and production of offshore oil and gas will have, and that the oil spill risk assessment is flawed. While the risk of an oil spill is reported as “unlikely”, the impact of the oil spill is reported as “high” and “very high”. They argue that an oil spill is a “highly significant potential impact” that would be felt “most acutely” by the West Coast fishers like Aukotowa “as well as across the country and for years after the event”.
They also argue that the impact assessments failed to consider the socio-economic impacts on the Aukotowa fishers, who have no other form of employment, and whose livelihoods will be destroyed by an event like an oil spill.
The Mozambican government has announced a natural gas discovery in the Inhambane Province in the south of the country.
The new find is the result of the first well, drilled by Sasol, the South African synfuels giant, in the Pande and Temane onshore area (PT5-C), located in the Mozambique Basin.
Filimão Suaze, spokesperson of Mozambique’s ministerial cabinet, made the announcement in Maputo, Tuesday, November 5, 2024
He said that the commercial viability of this discovery has yet to be assessed and that “additional evaluations will follow to determine its size and verify its viability”.
The PT5-C onshore area was awarded in 2018 to Sasol Petroleum Mozambique Exploration Limitada (70%) and Empresa Nacional de Hidrocarbonetos (30%). The asset is separate from the two other (1) PSA and (2) PPA areas in the vicinity, where Sasol already has integrated hydrocarbon developments, including gas to power, gas export and latterly LPG.
